1. Field of the Invention
The present invention relates generally to methods and apparatus for the control of production wells and injection wells. More particularly, the invention relates to methods and apparatus for monitoring and controlling oil and gas production wells or zones in a well and injection wells from a remote location or on site by a completely self contained intelligent system.
2. Background of the Related Art
The control of oil and gas production from wells constitutes an on-going concern of the petroleum industry due, in part, to the enormous monetary expense involved, as well as the risks associated with environmental and safety issues. Production well control has become particularly important and more complex in view of the industry wide recognition that wells having multiple branches (i.e., multilateral wells) will be increasingly important and commonplace. Such multilateral wells include discrete production zones which produce fluid in either common or discrete production tubing. In either case, there is a need for controlling zone production, isolating specific zones and monitoring each zone in a particular well.
Lift Systems
One type of production system utilizes electrical submersible pumps (ESP) for pumping fluids from downhole. Such pumps may comprise impeller driven pumps or submersible progressing cavity pumps (SPCP's). Also, pumps powered by pressurized hydraulic fluid driven impellers or the like can be used. In addition, there are other types of production systems for oil and gas wells, such as plunger or rod driven progressing cavity pumps (PCP's), plunger lift and gas lift. Plunger lift production systems include the use of a small cylindrical plunger which travels through tubing extending from a location adjacent the producing formation down in the borehole to surface equipment located at the open end of the borehole. In general, produced fluids which collect in the borehole and inhibit the flow of fluids out of the formation and into the wellbore, are collected in the casing/tubing. Periodically, the tubing is opened and the accumulated reservoir pressure is sufficient to force the plunger up the tubing. The plunger carries with it to the surface a load of accumulated fluids which are ejected out the top of the well thereby allowing hydrocarbon or gas to flow more freely from the formation into the wellbore and be delivered to a distribution system at the surface. After the flow of gas has again become restricted due to the further accumulation of fluids downhole, a valve in the plunger or the tubing at the surface of the well is closed so that the plunger then falls back down the tubing and is ready to lift another load of fluids to the surface upon the reopening of the valve.
Rod driven pumps are in quite common usage in relatively shallow producing wells. A surface source of motive power repetitively lifts and lowers a pump plunger or turns a shaft in the PCP inside a production tubing string via a rod string which extends from the surface. Each plunger stroke or rod revolution in the PCP lifts a quantity of produced fluid to the surface distribution system. The volume of fluid produced by each stroke of the rod driven plunger or shaft revolution of the PCP is a function of the permeability of the producing formation and the formation pressure causing flow into the casing/tubing annulus through the production perforations in the casing, or in a gravel pack completion, through a screen or liner. It will be appreciated by those of skill in the art that some type of control of the opening or closing of the perforations or the screen or liner to fluid flow could, in an intelligent completion system such as that of the present invention, could be used to control undesired water entry such as that caused by “water coning.” Such control can also be provided, for example, by the use of a sliding sleeve device such as that described subsequently herein to mask or unmask a screen, liner, or perforations by its motion.
A gas lift production system includes a valve system for controlling the injection of pressurized gas from a gas source, such as another gas well, a gas zone in the same well, or a compressor, into the borehole. The pressure from the injected gas, when permitted to enter the tubing via one or more gas lift valves allows accumulated formation fluids to flow up a production tubing extending along the borehole to remove the fluids and restore the free flow of gas and/or oil from the formation into the well. In wells where liquid fall back is a problem during gas lift, plunger lift may be combined with gas lift to improve efficiency. All of the foregoing types of lift systems can be referred to as artificial lift systems. In some wells, of course, with adequate producing formation pressure, no artificial lift system is required.
In both plunger lift and gas lift production systems, there is a requirement for the periodic operation of a motor valve at the surface of the wellhead to control either the flow of fluids from the well or the flow of injection gas into the well to assist in the production of gas and liquids from the well. These motor valves have been conventionally controlled by timing mechanisms and are programmed in accordance with principles of reservoir engineering which determine the length of time that a well should be either “shut in” and restricted from the flowing of gas or liquids to the surface and the time the well should be “opened” to freely produce. Generally, the criteria used for operation of the motor valve is strictly one of the elapse of a preselected time period. In most cases, measured well parameters, such as pressure, temperature, etc., are used only to override the timing cycle in special conditions.
It will be appreciated that relatively simple, timed intermittent operation of motor valves and the like is often not adequate to control either outflow from the well or gas injection to the well so as to optimize well production. As a consequence, sophisticated computerized controllers have been positioned at the surface of production wells for control of downhole devices such as the motor valves or the gas lift valves.
In addition, such computerized controllers can be used to control other downhole devices such as hydro-mechanical safety valves or sliding sleeve valves. Microprocessor-based controllers are also used for zone production control within a well and, for example, can be used to actuate sliding sleeves and inflatable or expandable packers by the transmission of a surface command to downhole microprocessor controllers and/or electromechanical control devices.
Sensor Systems
The surface controllers may also be connected to downhole sensors which transmit information to the controller such as pressure, temperature and flow rate. This data is then processed at the surface by the computerized control system. Electrically submersible pumps (ESP's) or SPCP's can use pressure and temperature readings received at the surface from downhole sensors to change the speed of the pump in the borehole. As an alternative to downhole sensors, wire line production logging tools are also used to provide downhole data on pressure, temperature, flow, gamma ray and pulse neutron, or other formation characteristics using a wire line surface unit.
Prior Control Systems
There are numerous patents related to the control of oil and gas production wells. In general, these patents relate to surface control systems using a surface microprocessor or downhole control systems that are initiated by surface generated control signals. The surface control system patents generally disclose computerized systems for monitoring and controlling a gas/oil production well whereby the control electronics is located at the surface and communicates with sensors and electromechanical devices near the surface. A example of a surface control system is described in U.S. Pat. No. 4,633,954, Dixon et al., which is hereby incorporated by reference in its entirety. The downhole control system patents generally disclose downhole microprocessor controllers, electromechanical control devices and sensors. An example of a downhole control systems is described in U.S. Pat. No. 5,273,112, Schultz, which is hereby incorporated by reference in its entirety.
In another method of controlling the production well, the surface system is connected to a variable frequency drive system that varies the speed of the artificial lift system based on the pressure and flow information downhole and transferred to the surface controller. A more advanced control system links the surface control via radio communication or cellular phone to a remote controller, and the data received from the downhole monitoring system is transferred from the surface controller to the processor at the remote location on a regular basis. Changes to the well operating parameters may then be sent from the remote controller to the surface controller via radio communication or cellular phone on a regular basis. However, such systems do not provide flexibility in the location of access of the human operators because the physical locations of the surface controllers and the remote controller dictate the location from which the production parameters can be controlled and changed. Furthermore, such prior art systems do not provide flexibility in the choice of their mode of operation as to controlling one zone, one well, or an entire hydrocarbon production from a field.
While it is well recognized that hydrocarbon production wells will have increased production efficiencies and lower operating costs if surface computer based controllers and downhole microprocessor controllers (actuated by external or surface signals) of the type discussed hereinabove are used, the presently implemented control systems nevertheless suffer from other drawbacks and disadvantages.
One significant drawback of present production well control systems involves the extremely high cost associated with implementing changes in well control and related workover operations. Presently, if a problem is detected at the well, the customer is required to send a drawworks or rig to the wellsite at an extremely high cost (e.g., five million dollars for 30 days of offshore work). The well must then also be shut in during the workover causing a large loss in revenues (e.g. 1.5 million dollars for a 30 day period). Associated with these high costs are the relatively high risks of adverse environmental impact due to spills and other accidents as well as potential liability of personnel at the rig site. Of course, these risks can lead to even further costs. Because of the high costs and risks involved, in general, a well operator may delay important and necessary workover of a single well until other wells in that area encounter problems. This delay may cause the production of the well to decrease or be shut in until the rig is brought in. The system of the present invention offers retrievable pumps, controllers, and/or sensor modules without the need for a full derrick, drawworks and a casing or tubing pulling operation.
Therefore, there is a need for a system for monitoring and controlling production wells that provides substantially “real time” data to an operator and which allows an operator to control the production operation from a remote location and which offers greater flexibility and retrievable system components.